High Temp H2/H2S Corrosion | Materials and Corrosion Control
| Damage Mechanism | High Temp H2/H2S Corrosion |
| Damage Description | The presence of hydrogen in H2S streams increases the severity of high temperature sulfide corrosion at temperatures above about 450°F (260°C). This form of sulfidation usually results in a uniform loss in thickness within hot circuits of hydroprocessing units.
· Damage occurs in piping and equipment in units where high temperature H2/H2S streams are found including all hydroprocessing units, such as hydrotreaters and hydrocracking units. · Increased corrosion can occur at areas of higher velocity or turbulent flow, or on the topside of horizontally oriented furnace tubes and downstream of hydrogen injection points · Higher corrosion rates are found in gas oil hydrocrackers than naphtha desulfurizers by a factor of almost ‘2’. |
| Affected Materials | · Carbon steel
· 9Cr-1Mo and type 410 SS offer better corrosion resistance but for severe H2/H2S Corrosion service, 300 Series SS is required |
| Control Methodology | Principal factors are temperature, the presence of hydrogen, concentration of H2S and the alloy composition. · Damage is minimized by using alloys with high %Cr · 300 Series SS such as Types 304L, 316L, 321 and 347 are highly resistant at service temperatures. |
| Monitoring Techniques | · OSI, T & H2S trending
· UT, VT and RT thickness readings are used to monitor loss in thickness. · Verify operating temperatures compared to design. · Process simulations should be checked periodically to confirm that H2S levels have not significantly increased compared with design |
| Inspection Frequency | · OSI & T trending every shift |
| KPIs | · Ensure T, H2S & alloy installed give predicted corrosion rates below 10 mpy, using Couper-Gorman curves for High Temp H2/H2S Corrosion |
| Reference Resources (Standards/GIs/BPs) | · API RP 571 (DM #4)
· API RP 939C · NACE PUBL 34103 (2004) |